Methods of enhancing production from oil and gas wells with lower end productivity indices, such as depletion wells, otherwise known as stripper wells, have continually been developed and improved to make oil and gas resources recoverable that otherwise could not be produced economically. The gas-lift method of fluid purging is one such method that was developed over a decade ago. Through continual refinement, gas-lift methods have been established as a viable means of enhancing oil and gas production.
In a typical oil and gas well, a well bore is created in the earth and a casing is inserted into the well bore. The casing encloses a tubing string which passes through a well head located at the top of the well bore. The casing has a plurality of perforations which are positioned at a selected depth within the subterranean formation and which allow oil and gas to enter the casing near the lower end of the tubing string. The depth of the perforations depends upon the characteristics of the subterranean formation, and generally varies from about 1,000 feet to over 15,000 feet below the earth's surface. The composition of the fluid which enters the casing depends upon the conditions of the subterranean formation and on the particular production techniques employed, but will generally be a mixture of liquid (including oil and water) and gases (including natural gas).
Ideally, pressure from the formation forces fluid through the tubing string to the earth's surface, where a production line delivers the liquid and gas mixture to a separator. A choke valve on the production line variably restricts the fluid flow rate to provide a desirable back pressure in the tubing string. The choke valve is controlled by a conventional controller, which may be responsive to a number of well conditions, such as subterranean pressure (i.e., "bottom-hole" pressure) and casing pressure.
A well with a relatively high bottom-hole pressure and a relatively high productivity index can be operated continuously, in part by controlling the back pressure on the tubing string to produce a gas velocity that effectively carries the liquid up the tubing string to the production line. If the gas velocity is too great, the gas will over-run the liquid in the tubing string and no liquid will be produced. On the other hand, if the gas velocity is too low, then the gas will not have sufficient energy to carry the liquid up the tubing string to the production line.
A gas-lift method is commonly used in a continuously flowing well to enhance production. The gas-lift methodology works by injecting a relatively small volume of high pressure gas, such as air, into the tubing string at some predetermined depth to assist the bottom-hole pressure to carry the fluid in the tubing string to the production line. To inject the required gas, the well is provided with a casing line through which the gas is injected to pressurize the casing. The injected gas enters the tubing string through one or more of a plurality of conventional control valves located along the tubing string. Once injected into the tubing string, the expanding injection gas aerates and lightens the fluid column thereby helping the bottom-hole pressure to deliver the fluid to the production line.
A well with a relatively low bottom-hole pressure and a relatively low productivity index is typically equipped with a conventional standing valve which is placed in the bottom of the tubing string. A conventional standing valve functions simply as a check valve which allows upward flow of fluid from the well bore into the tubing string, but prohibits downward flow of fluid from the tubing string into the well bore. In this manner, the conventional standing valve accumulates fluid in the tubing string.
Removing the fluid which accumulates above the conventional standing valve in the tubing string of a well with a low bottom-hole pressure is problematic because of the diminished pressure and because such a well typically produces higher viscosity oil. A common way to remove the fluid from the tubing string is to operate the well using an intermittent gas-lift method.
Using the intermittent gas-lift method, gas enters the tubing string at a high instantaneous rate for a short period to purge the liquid accumulated in the tubing string as a slug. Thus, the intermittent gas-lift method uses high pressure gas at a sufficient volume and pressure to lift the liquid slug to the production line at a maximum velocity, while minimizing aeration and fluid fall-back. To create the intermittent nature of the purging, the choke valve is periodically closed to build up gas-lift pressure. The gas-lift pressure may come only from the subterranean formation or it may be supplementally injected into the casing. Opening the choke valve after building pressure creates a pressure differential that purges the liquid as a slug as the pressure differential equalizes. Purging the liquid slug at a maximum velocity requires controlling numerous process variables, such as purging frequency, injection pressure, and tubing size. A conventional packer is typically used to minimize the effective volume of casing that must be pressurized.
The efficiency of using an intermittent gas-lift method to lift a slug of fluid leaves much to be desired. Lifting a slug of liquid by the gas-lift method causes the gas to increasingly intermix and channel through the liquid, which aerates the liquid and imparts a velocity profile to it. When gas channels completely through the liquid, the gas imparts turbulence to the liquid. Turbulence is undesirable because it diminishes purging efficiency by causing liquid to fall back within the tubing string.
A common solution to this problem has been to use the gas-lift method in conjunction with a lifting plunger. The lifting plunger is positioned in the tubing string to provide a mechanical barrier between the pressurized gas upstream of the lifting plunger and the liquid slug downstream of the lifting plunger. One skilled in the art will recognize that the use of the lifting plunger in conjunction with the standing valve permits liquid pumping efficiency that is comparable to that of sucker rod pumping, but at a fraction of the cost. To outfit a well with a gas-lift and lifting plunger can typically cost about $4,000, which compares to about $30,000 to outfit a well with a pumpjack.
The method of intermittent purging of the liquid with a plunger and a gas-lift method is like that described previously, except that the pressure differential resulting from opening the choke valve acts across the lifting plunger which, in turn, pushes the accumulated liquid up the tubing string. The plunger can be retained at the top of the tubing string by a conventional lubricator after the plunger has purged the tubing string. One skilled in the art will recognize that following a purge cycle it is preferable to retain the plunger in this manner so that fluid can be continuously produced from the subterranean formation without obstruction in the tubing string by the plunger.
As the well continuously produces, a portion of the liquid carried by the gas falls back within the tubing string. A timer is typically used to anticipate when enough liquid has accumulated to warrant an intermittent purging cycle. To purge the liquid, the choke valve is closed and the plunger is released. To prevent damage to the plunger and the standing valve resulting from the plunger free-fall, a conventional bumper spring is latched to the standing valve to absorb the impact of the returning plunger. The choke valve remains closed long enough to build the desired gas-lift pressure, and then re-opened to purge the liquid.
The benefits of using the lifting plunger are well known by one skilled in the art, including: 1) channeling of gas through the liquid is eliminated, 2) injection ratios per barrel of liquid are considerably lower because of a solid interface between the gas and liquid phases, 3) lower gas-lift pressures can be used because lifting energy is conserved, and 4) continuous wiping action of the plunger against the casing prevents contaminant build-up, such as the build-up of paraffin, salt, and ice.
There are various types of lifting plungers, such as those taught by U.S. Pat. No. 4,007,784 issued to Watson, and U.S. Pat. No. 4,410,300 issued to Yerian. These and other references teach diverse schools of thought in plunger design, ranging from very complicated to very simple construction. At a most general level, lifting plungers are categorized into three basic types: 1) the solid type, 2) the expanding type, and 3) the bypass type.
The conventional standing valve used in combination with the lifting plunger functions simply as a check valve which allows upward flow of fluid from the well bore into the tubing string, but prohibits downward flow of fluid from the tubing string into the well bore. In this manner, the conventional standing valve accumulates a fluid slug in the tubing string.
The conventional standing valve has a body which has a central passageway that provides fluid communication through the valve. A valve seat is supported by the body within the passageway. The valve seat has an annulus that is coaxial with the central axis of the central passageway. A valve ball is supported by the valve seat in one mode wherein the ball sealingly engages against the valve seat and prevents downward flow of fluid through the annulus. In another mode the ball freely lifts upward off the valve seat to permit upward flow of fluid through the annulus. By this construction, one skilled in the art will recognize the conventional check valve construction of the prior art standing valve which permits fluid flow upward through the standing valve from the well bore into the tubing string, but prevents reverse flow downward through the standing valve from the tubing string into the well bore.
Fluid from the well bore flows upward through the conventional standing valve by displacing the ball from the valve seat. The fluid is thereafter retained in the tubing string as the weight of the accumulated fluid imparts a downward seating force on the ball against the valve seat. A generally recognized problem in the industry, however, is that often more fluid will accumulate above the standing valve than can be purged by the gas-lift method. Although the process variables affecting the intermittent purge cycles can be adjusted, the wells are for the most part are unattended. Effective control of the accumulated fluid head, therefore, requires anticipating the accumulation rate of fluids between purge cycles.
The frequency of purge cycles is desirably held to a minimum because excessive purge frequency results in a greater likelihood of premature tubing string failure or of lodged plungers within the tubing string. Changes in either bottom-hole pressure or fluid flow rate are likely to create an unanticipated accumulation of fluid in the tubing string that is heavier than the purging capability of the gas-lift method. It is also common for a mechanical failure to prevent fill or proper purging, such as a choke valve or controller failure. A purge failure with a conventional standing valve will result in the continual accumulation of fluid head until eventually the head pressure of the accumulated fluid shuts the gas flow in below the head.
Upon discovering a purge failure, the well operator is usually faced with only one recuperative option, that of "swabbing" the well to remove the accumulated fluid. This process of swabbing the well entails costly down time and service work.
Thus, despite these and other advances in the art, there is a need in the industry for a solution to the problem of purge failure in gas-lift methods of production. The present invention provides a device for effectively regulating the amount of fluid which accumulates in the tubing string so that the fluid can be reliably purged when using gas-lift methods. The present invention enhances the efficiency of gas-lift production, eliminates the need for swabbing, and offers other advantages over the prior art which will be recognized by those skilled in the art.